Multi-Acting Circulation Tool for One-Trip Casing Cut-and-Pull

ABSTRACT

Disclosed embodiments may relate to methods and devices which may assist in removal of casing from a wellbore, for example during abandonment operations. In an embodiment, the tool device may have a sleeve rotationally disposed on a housing body, such that rotation may operate to switch the tool between two configurations. In the first configuration, the tool may allow fluid flow down the length of the tool string through the longitudinal bore, and then back up to the surface through the annular space outside the housing. In the second configuration, the tool may allow fluid flow from the bore of the tool to the annular space, and then downward in the annular space.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional of and claims benefit under 35 U.S.C. §119 to co-pending U.S. Provisional Patent Application Ser. No. 62/078,798, filed on Nov. 12, 2014, and entitled “Multi-Acting Circulation Tool for One-Trip Casing Cut-and-Pull”, which is hereby incorporated by reference for all purposes as if reproduced in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Applicants have developed tool embodiments allowing for selective diversion of fluid flow within a wellbore/tool string. Such disclosed embodiments may allow for more efficient ways to remove casing from wellbores during well abandonment operations, for example. By way of illustration, disclosed embodiments may relate to tools to assist in cutting and removing casing in advance of extraction, allowing for the related cutting and pulling operations to take place during a single trip of the tool string downhole. And disclosed embodiments may also allow for tool configuration (and thus fluid flow paths) to be altered multiple times during a single trip downhole, for example if more than one cutting operation is needed for casing removal. Persons of skill will appreciate the advantages arising from such tool embodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.

FIG. 1A illustrates, as a longitudinal cross-section view, an exemplary embodiment of a tool in its first configuration (e.g. with the sleeve located in its first position rotationally with respect to the housing/mandrel);

FIG. 1AA illustrates a lateral/radial cross-section of FIG. 1A (taken at F-F), showing alignment of the annular flow ports in the face flange/seal with the bypass ports (e.g. to allow fluid flow in the annular space, since the bypass is open);

FIG. 1AB illustrates a lateral/radial cross-section of FIG. 1A (taken at D-D), showing the rotational position retaining element;

FIG. 1AC illustrates a lateral/radial cross-section of FIG. 1A (taken at E-E), showing the stabilizer elements;

FIG. 1AD is a detail of the bypass ports of FIG. 1A;

FIG. 1B illustrates, as a partial longitudinal cross-section view, the tool embodiment of FIG. 1A in its second configuration (e.g. with the sleeve located in its second position rotationally with respect to the housing/mandrel);

FIG. 1BA illustrates a lateral/cross-section view of FIG. 1B (taken at K-K), showing that the annular flow ports in the face flange/seal are out of alignment with the bypass ports (e.g. so there can be no fluid flow upward in the annular space beyond the bypass element, since the bypass is closed);

FIG. 1BB illustrates a lateral/cross-section view of FIG. 1B (taken at L-L), showing alignment of the radial ports with the mandrel ports to allow radial flow of fluid from the bore to the annular space);

FIG. 1BC illustrates a detail (cut-away) portion of the sleeve in perspective view, showing the rotational position retaining element of the sleeve in more detail;

FIG. 2 illustrates schematically a tool string with an exemplary tool (such as the tool of FIG. 1A for example) located with a cased wellbore;

FIGS. 3A-3C illustrate schematically an exemplary tool in its first configuration (e.g. with the sleeve in its first position, sealing the mandrel ports and aligning the annular flow ports with the bypass ports to allow annular fluid flow), with FIG. 3A illustrating in longitudinal cross-section an exemplary fluid flow for such a configuration, FIG. 3B illustrating in cut-away side view how the sleeve blocks/seals the mandrel port(s) in the first configuration/position, and FIG. 3C illustrating in radial cross-sectional view how the annular flow ports are aligned with the bypass ports in the first configuration;

FIGS. 4A-4D illustrate schematically an exemplary tool in its second configuration (e.g. with the sleeve in its second position, sealing the bypass (with the annular flow ports out of alignment with the bypass ports) while allowing radial flow from the bore to the annular space), with FIG. 4A illustrating in longitudinal cross-section an exemplary fluid flow for such a configuration, FIG. 4B illustrating in cut-away side view alignment of the radial ports of the sleeve with the mandrel ports in the second configuration, and FIG. 4C illustrating in radial cross-section view how the annular flow ports are out of alignment with the bypass ports (thereby preventing annular fluid flow upward) in the second configuration;

FIG. 4D is a schematic illustration similar to that of FIG. 4A (showing the tool in its second configuration), in which the tool and tool string are shown in place within the casing of the wellbore, the cut of the casing is shown, and the fluid flow (down the bore, out the aligned radial and mandrel ports and into the annular space, downward in the annular space, out the cut, and upward from the cut in the space between the casing and the wellbore) of the second configuration is more fully illustrated;

FIG. 5 illustrates schematically the tool string moved upward in the cased wellbore and configured (in its first configuration) to make a second/subsequent cut of the casing;

FIG. 6 illustrates schematically the tool string in its second configuration after making the second/subsequent cut of the casing; and

FIG. 7 illustrates schematically the tool string pulling the cut casing from the wellbore.

DETAILED DESCRIPTION

It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the disclosed systems and methods may be implemented using any number of techniques, whether currently known or not yet in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, but may be modified within the scope of the appended claims along with their full scope of equivalents.

The following brief definition of terms shall apply throughout the application:

The term “up”, “uphole”, “above”, or the like, when used in reference to well or the tool string for example, shall mean towards the surface or towards the top or away from the end of the well; similarly, the term “down”, “downhole”, “below”, or the like shall mean away from the surface or towards the bottom or end of the well;

The term “comprising” means including but not limited to, and should be interpreted in the manner it is typically used in the patent context;

The phrases “in one embodiment,” “according to one embodiment,” and the like generally mean that the particular feature, structure, or characteristic following the phrase may be included in at least one embodiment of the present invention, and may be included in more than one embodiment of the present invention (importantly, such phrases do not necessarily refer to the same embodiment);

If the specification describes something as “exemplary” or an “example,” it should be understood that refers to a non-exclusive example;

The terms “about” or approximately” or the like, when used with a number, may mean that specific number, or alternatively, a range in proximity to the specific number, as understood by persons of skill in the art field (for example, +/−10%); and

If the specification states a component or feature “may,” “can,” “could,” “should,” “would,” “preferably,” “possibly,” “typically,” “optionally,” “for example,” “often,” or “might” (or other such language) be included or have a characteristic, that particular component or feature is not required to be included or to have the characteristic. Such component or feature may be optionally included in some embodiments, or it may be excluded.

Embodiments may relate generally to methods and devices which may assist in removal of casing from a wellbore, for example during abandonment operations. More specifically, the device and method embodiments might relate to cutting of the casing, cleanout operations to loosen the casing in the wellbore (by, for example, flowing fluid between the casing and the surface of the wellbore), and/or extraction of the cut casing from the wellbore. And typically, the device and method embodiments might allow such cutting-and-pulling operations to be performed using only one trip of the tool string downhole (e.g. performed in a single trip, for additional efficiency, thereby offering the potential to save significant money), for example by selectively diverting fluid flow.

So, disclosed embodiments may relate generally to tool embodiments for diversion of fluid flow, typically within a wellbore and/or tool string. In some instances, typical embodiments of such diverter tools may relate to casing cutting and pulling operations as currently performed in well abandonment operations. Typically, the casing is cut at a predetermined depth where the casing string above must be removed from the well, so that adequate well barriers can be put in place to secure the well. The casing cut may be performed using an expanding-blade cutter, which typically may be rotated by the work string, or alternatively by a positive displacement mud motor run directly above the cutter in the tool string. The motor typically is powered by fluid circulated through the drill pipe work string (e.g. tool string), which passes through the motor. This motor's stator/rotor combination may create rotation and torque to power the cutter. Fluid typically then would exit the cutter when in operation and would be circulated back up the casing to the surface. Once the cut has been completed, the cutting string would conventionally be removed from the well. The next operation typically might be to circulate fluid around the outside of the casing which was previously cut to remove old drilling mud and any solids which may prevent or otherwise hinder the casing from being removed from the well. To perform this operation conventionally (e.g. without a disclosed diverter tool), a second tool string would be run in the well, which includes a casing pack off tool and a casing spear. Once the spear is latched into the casing, the casing pack off prevents fluid circulation up hole through the annulus between the casing that has been cut and the drill pipe. So, as fluid is pumped down the drill pipe it can only go out through the cut in the casing and around the outside of the casing that was cut. This would provide the necessary circulation around the outside of the casing to remove mud, debris and gas before pulling the casing. Once clean out circulation has been completed, the spear and jars would be used to pull the casing from the well. The conventional process described above is completed in two drill pipe/tool trips into the well, due to the need to circulate fluids up the casing-drill pipe annulus while making the casing cut, while then needing this annulus to be closed off to allow clean-up circulation around the outside of the casing after the cut has been made. The presently disclosed diverter tool embodiments allow for this operation to be performed in only one trip using a selective annular sealing device that would allow circulation in the casing-drill pipe annulus during the cut, but then be able to seal off the annulus (to prevent fluid upflow) after the cut has been made. Performing this cutting and pulling operation in only one trip should save substantial rig time and be more cost effective for the operator. Furthermore, disclosed embodiments may also allow for tool configuration (and thus fluid flow paths) to be altered multiple times during a single trip downhole, for example if more than one cutting operation is needed for casing removal (such that multiple cuts might be performed in a single trip downhole). Thus, disclosed tool embodiments represent significant improvements for such casing cut-and-pull operations.

In such embodiments, the tool device may have a sleeve rotationally disposed on a mandrel/housing body, such that rotation (for example, rotation of the tool string from the surface) may operate to selectively switch the tool between two configurations (for example, by moving the sleeve from a first position to a second position). In the first configuration, the tool may allow fluid flow down the length of the tool string through the longitudinal bore (for example, in order to power cutting of the casing), and then back up to the surface through the annular space outside the housing (within the casing—e.g. between the housing and the casing). So in the first configuration, the tool typically allows for cutting of the casing (by for example, directing fluid in the bore downward to the motor for the cutter and allowing circulation back to the surface in the annular space (between the tool string and the casing)). In the second configuration, the tool may allow fluid flow from the bore of the tool to the annular space, and then downward (for example, towards the cut). This may allow fluid to exit the cut and flow upward on the outside of the casing (e.g. between the casing and the wellbore surface). The goal might be to circulate fluid up the outside of the casing all the way to the surface, for example in order to loosen the casing within the wellbore to improve extraction of the casing from the wellbore. So in the second configuration, the tool typically allows for circulation through the cut and upward between the casing and the wellbore (for example, by sealing the annular space between the housing of the tool and the casing and opening flow radially from the bore to the annular space (for example, below the location of the sealed section of the annular space)). And by using the rotational position of the sleeve with respect to the housing to set the configuration of the tool, the tool configuration is operable to switch (between the first and second configuration/position) multiple times if desired.

So for example, disclosed embodiments might include a tool for use in a downhole tool string within a cased wellbore, comprising: a housing/mandrel adapted to be made up as part of the tool string, with a longitudinal bore therethrough, one or more mandrel ports penetrating radially from the longitudinal bore through the housing (operable to allow fluid flow from the bore to the annular space between the housing and the casing), and a bypass element located above the one or more mandrel ports and having one or more bypass ports therethrough (operable to allow fluid flow in the annular space (e.g. annular flow between the housing and the casing) from below the bypass element to above the bypass element); a packer cup (or other annulus seal element) typically located about/around the exterior of the bypass element of the housing and operable to engage (in a sealing manner) the casing (e.g. cased wellbore) and/or the bypass element (for example, to prevent fluid flow between the exterior of the bypass element and the cased wellbore—it should be understood that the term “packer cup” as used in this application is intended to be broadly considered as any annulus seal element and is not merely limited to any specific packer cup embodiment, so the terms “packer cup” and “annulus seal element” may be used interchangeably herein); and a sleeve disposed on the exterior of the housing for rotational movement with respect to the housing between a first position and a second position. Typically, the sleeve would comprise one or more radial ports (corresponding to the mandrel ports in the housing body and/or located on the same radial plane as the mandrel ports in the housing and/or spaced about the circumference of the sleeve in a manner corresponding/matching the spacing of the mandrel ports in the housing), a face flange/seal operable to interface/engage with the bypass element to seal annular flow therethrough, and a rotational position retaining element (operable to restrict rotational movement of the sleeve). For example, the rotational position retaining element might comprise two or more drag blocks (e.g. having spring loaded dog elements that hold/grip the casing to restrict rotation of the sleeve—so that when the housing/tool string is rotated, the sleeve does not rotate (or does not rotate as much, thereby imparting a rotational offset between the housing/tool string and the sleeve)). Additionally, the face/flange seal typically would comprise one or more annular flow ports (corresponding to the bypass ports and/or located in a longitudinally adjacent plane as the bypass ports and/or spaced about the circumference of the face seal in a manner corresponding/matching the spacing of the bypass ports). In the first position of the sleeve, the radial ports in the sleeve would not be aligned with the mandrel ports in the housing body (such that the sleeve closes/seals the mandrel ports in the housing to prevent (radial) fluid flow from the bore to the annular space through the housing), but the annular flow ports in the face seal would be aligned with the bypass ports in the bypass element (such that fluid may flow (longitudinally) through the packer cup/bypass element in the annular space between the housing and the casing—e.g. allowing fluid communication in the annular space from below the packer cup to above the packer cup). In the second position of the sleeve, the radial ports in the sleeve would be aligned with the mandrel ports in the housing body (allowing (radial) fluid communication from the bore to the annular space, such that fluid in the bore may flow into the annular space), but the annular flow ports in the face seal would not be aligned with the bypass ports in the bypass element of the housing (such that the face flange/seal closes/seals the bypass ports to prevent (longitudinal) fluid flow in the annular space from below the packer cup to above the packer cup—e.g. the tool no longer allows annular fluid flow upward past the sealed packer cup/bypass element, since the bypass element would be closed). In other words, typically the sleeve would be operable to open and close the radial mandrel ports in the housing and the longitudinal bypass ports in the bypass element of the housing in an offsetting manner, such that when one is closed, the other is open, and vice versa. So for example, in some embodiments the two different types of ports in the tool (e.g. relating to radial flow from the bore to the annular space and relating to longitudinal flow in the annular space, for example upward past the bypass element) might have a 90 degree offset.

Typically, the tool would be operated by rotation of the housing (e.g. via rotation of the tool string), for example with respect to the sleeve (such that rotation of the position of the sleeve with respect to the housing would operate to shift the tool between configurations). In other words, rotation of the tool string one direction would typically position the sleeve in the first position (corresponding to the first configuration for the tool, for example), and rotation of the tool string the other direction would typically position the sleeve in the second position (corresponding to the second configuration for the tool, for example). So for example, the tool might be configured so that a right hand turn/rotation of the housing/tool string operates to place the sleeve in the first position (with bypass ports open (e.g. the annular flow ports of the sleeve aligned with the bypass ports) and mandrel ports in the housing closed (e.g. the radial ports of the sleeve out of alignment with the mandrel ports in the housing)), and a left hand turn/rotation of the housing/tool string operates to place the sleeve in the second position (e.g. close the bypass ports (e.g. the annular flow ports of the sleeve out of alignment with the bypass ports) and open the mandrel ports in the housing (e.g. the radial ports of the sleeve are aligned with the mandrel ports in the housing)).

Typically, the tool may be configured so that the sleeve is free (operable) to rotate with respect to the housing. In some embodiments, the sleeve would be operable to rotate approximately 90 degrees with respect to the housing. Often, the rotation of the sleeve with respect to the housing would be limited (e.g. allowing only a set amount of such rotation, before the sleeve would rotate with the housing). For example, the interface between the sleeve and the housing may include a stop element or mechanism, so that after a pre-defined amount of rotation of the sleeve with respect to the housing in one direction, the sleeve would rotate with the housing if additional rotation that direction occurs (and vice versa, the other direction). So for example, in some embodiments the sleeve's rotation might be limited to approximately 90 degree rotation with respect to the housing (e.g. so that the sleeve is operable to rotate approximately 90 degrees in shifting between its two positions/configurations). For example, one or more bolts (on the bypass element, for example) might be located (for sliding) within slots (which in some embodiments might be the annular flow ports) in the face flange that govern the allowed amount of rotation of the sleeve with respect to the housing.

In some embodiments, the packer cup (or other annulus seal element) may be configured to rotate freely (e.g. configured/operable for free rotation) with respect to the housing/bypass element. And typically, the longitudinal bore of the housing would also comprise a necked-down portion (e.g. with a smaller inner diameter) having a shoulder, typically located below the mandrel ports. This shoulder within the bore may serve as a ball/plug seat (for example, if a ball is dropped to seal the longitudinal bore, which might be useful to ensure full diversion of fluid from the bore to the annular space when the tool is in its second configuration). As used herein, ball is intended to be understood broadly as including any such plug element for blocking fluid flow through the longitudinal bore (for example, sealing the longitudinal bore after being pumped down to seat on a shoulder)).

Typically, the sleeve or face seal/flange of such embodiments might be biased upward against the bypass element. In other words, an exemplary tool might further comprise a spring, with the spring biasing the sleeve (or face flange) upward into contact with the bypass element (for example, to ensure a good seal therebetween). And some embodiments might further comprise stabilizer elements operable to help centralize the tool in the cased wellbore. Typically, such stabilizer elements would be configured to (freely) rotate with respect to the housing.

In use, the tool might often be used with a ball or plug element which is operable to seal the longitudinal bore, for example by seating on the shoulder of the necked-down portion of the longitudinal bore. Typically such a ball or plug might be used when the sleeve is in the second position (e.g. the tool is in its second configuration), to divert/direct fluid flow from the bore entirely through the mandrel ports and into the annular space. So the ball would be a separate element, distinct and apart from the housing/tool, which might be used in conjunction with the tool in only certain configurations to help direct/divert fluid flow. For example, prior to placement of the ball on the shoulder in the bore (e.g. when the longitudinal bore is open), all fluid pumped down the bore would typically flow entirely through the bore (e.g. below the tool in the tool string), but after placement of the ball on the shoulder in the bore (and when the tool is in its second configuration), fluid would flow entirely through the mandrel ports.

Typically, the tool would be made up into a tool string for use downhole. Such a tool string would typically include other elements. For example, a tool string (comprising the tool) might further comprising a cutter (for example, an expanding-blade cutter) and a motor, with the motor powering/driving the cutter and the motor being operable/configured to be powered/driven by fluid flow through the tool string (e.g. bore). In typical tool string embodiments, the motor and cutter would be located below the mandrel ports (e.g. below the tool). Additionally, the tool string would typically further comprise a spear (or other pulling tool for extracting the cut casing—as used herein, spear is intended to be interpreted broadly to include an actual downhole spear and/or any other such pulling tool for extracting cut casing from a wellbore). In embodiments, the spear might comprise a rotatable, resettable spear. Thus, the spear might be configured to be set with rotation of the tool string one direction (typically in the same direction as used to place the tool in its first configuration, for example to the right) and unset by rotation of the tool string the other direction (typically in the same direction used to place the tool in its second configuration, for example to the left). And in some embodiments, the tool string might also optionally include one or more magnets (e.g. located below the mandrel ports and/or above the cutter). Such magnets might be operable to capture any loose cutting shavings from the fluid flow (for example, before it circulates up to the tool (for example, the bypass ports of the tool)) and/or to the surface.

FIGS. 1A-1B illustrates an exemplary embodiment of a tool device, with FIG. 1A showing the tool 100 in its first configuration (e.g. with the sleeve 140 in its first position), and FIG. 1B showing the tool 100 in its second configuration (e.g. with the sleeve 140 in its second position). The tool 100 would typically be shifted between its first and second configurations based on rotation of the sleeve 140 with respect to the housing 110 (for example, by rotating the housing by rotation of the tool string from the surface, while the sleeve's rotational position is retained/restrained to provide rotational offset). In the embodiment of FIGS. 1A and 1B for example, the tool may be moved into its first configuration by right hand rotation, and may be moved into its second configuration by left hand rotation. In other words the tool of FIGS. 1A-B is configured so that a right hand turn/rotation of the housing/tool string operates to place the sleeve in the first position (with bypass ports open (e.g. the annular flow ports of the sleeve aligned with the bypass ports) and mandrel ports in the housing closed (e.g. the radial ports of the sleeve out of alignment with the mandrel ports in the housing)), and a left hand turn/rotation of the housing/tool string operates to place the sleeve in the second position (e.g. close the bypass ports (e.g. the annular flow ports of the sleeve out of alignment with the bypass ports) and open the mandrel ports in the housing (e.g. the radial ports of the sleeve are aligned with the mandrel ports in the housing)). In the embodiment of FIGS. 1A-B, approximately 90 degrees of rotation would operate to switch the tool between configurations. FIGS. 1AA, 1AB, 1AC, 1AD, 1BA, 1BB, and 1BC are related to FIGS. 1A and 1B and may help to further illustrate aspects/elements of the tool in either the first or second configuration (as will be discussed in greater detail below).

So in FIG. 1A, the tool 100 comprises a housing 110, which has a longitudinal bore 115 therethrough and one or more mandrel ports 117 (penetrating the housing/mandrel 110 radially, for example to provide a flow path outward from the bore 115 towards the annular space outside the housing). The housing 110 of FIG. 1A has an outer diameter which is less than the inner diameter of the casing of the wellbore to be serviced. The housing 110 also is configured so that it may be made-up into a tool string (for example having threaded portions on the top and/or bottom sections allowing for mating with other tool string elements). In FIG. 1A, a portion of the housing is the bypass element 120, which contains one or more bypass ports 125 (as seen, for example in FIG. 1AA) extending in the longitudinal direction through the bypass element 120 (thereby providing a flow path for the annular space 182 which may be schematically parallel to the longitudinal bore 115, as shown in FIGS. 2-3A-3C for example). And located about the bypass element 120 is a packer cup 130. The packer cup 130 forms a seal about the bypass element 120 (at the contact points about the circumference), and is operable to form a seal with the casing 180 when the tool 100 is in place within a cased wellbore (with its inner diameter being approximately equal to that of the bypass element and with its outer diameter being approximately equal to the inner diameter of the casing, as FIG. 2 illustrates for example). Thus, when the tool 100 is in place in the cased wellbore, the packer cup 130 prevents any flow past (the exterior of) the bypass element 120 (e.g. the packer cup 130 may seal the annular space about the bypass element). In other words, the bypass ports 125 in the bypass element 120 are the only avenue for annular flow in the annular space, due to sealing engagement of the packer cup 130 with the cased wellbore. In the embodiment of FIG. 1, the packer cup 130 may be free to rotate about the bypass element 120.

Located about the exterior of the housing 110 of FIG. 1A is a sleeve 140, which is operable to rotate with respect to the housing 110. Rotation of the sleeve (from a first position to a second position) may operate to move the tool from its first configuration (shown in FIG. 1A) to its second configuration (shown in FIG. 1B). The sleeve 140 of FIG. 1A is typically located longitudinally so that it can interface with the mandrel ports 117 and the bypass element 120 (such that, for example, the sleeve 140 spans a distance downward from the bypass element 120 to at least below the mandrel ports 117). The sleeve 140 also comprises one or more radial ports 142, which typically are located on the same radial plane (e.g. the same longitudinal distance downward along the tool string) as the mandrel port(s) 117, and which are typically spaced about the circumference of the sleeve 140 in a manner corresponding to the spacing of the mandrel ports 117 on the circumference of the housing 110 (and typically, the radial ports might be sized to match the corresponding mandrel ports). Such location and spacing allows the radial ports 142 of the sleeve to either be aligned with the mandrel ports 117 (e.g. so the sleeve can open the mandrel ports, for example in the second rotational position of the sleeve), or allows the radial ports 142 to be out of alignment with the mandrel ports (e.g. so the sleeve can close the mandrel ports, for example in the first rotational position of the sleeve). In other words, the radial ports 142 are located and spaced on the sleeve 140 so that rotation of the sleeve may be used to open or close the mandrel ports (depending on the alignment of the radial ports with the mandrel ports).

Additionally, the sleeve 140 of FIG. 1A comprises a face flange/seal 144, which is typically located on the upper end of the sleeve 140 and typically has a larger outer diameter than the portion of the sleeve 140 having the radial ports 142. In other words, the face flange/seal 144 of FIG. 1A extends out laterally from the upper end of the main sleeve body. The face flange/seal 144 comprises one or more annular flow ports 145, which are located and spaced on the face flange 144 in a manner corresponding to the spacing of the bypass ports 125 in the bypass element 120 of the housing (and typically, the annular flow ports might be sized to be at least as large as (and often larger than) the corresponding bypass ports). Such location and spacing allows the annular flow ports 145 of the sleeve to either be aligned with the bypass ports 125 (e.g. so the sleeve can open the bypass ports, for example in the first rotational position of the sleeve), or allows the annular flow ports 145 to be out of alignment with the bypass ports 125 (e.g. so the sleeve can close the bypass ports, for example in the second rotational position of the sleeve). In other words, the annular flow ports 145 are located and spaced on the face flange 144 of the sleeve so that rotation of the sleeve may be used to open or close the bypass ports 125 (depending on the alignment of the annular flow ports with the bypass ports). The annular flow ports 145 of FIGS. 1A and 1B are radially offset from the radial ports 142 of the sleeve, so that when one set of ports are aligned to open flow in one direction, the other set of ports are out of alignment to prevent flow the other direction (and vice versa). Alternatively, the mandrel ports of the housing and the bypass ports might be radially offset. Regardless, the open position for the bypass ports should typically be radially offset from the open position for the mandrel ports. In FIG. 1A, for example, these ports have a 90 degree offset (which may correspond to the maximum allowed rotation of the sleeve with respect to the housing in some embodiments). For example, when the radial ports 142 are aligned with the mandrel ports 117 (to allow flow radially from the bore outward), the annular flow ports 145 would be out of alignment with the bypass ports 125 (to block/prevent longitudinal annular flow upward in the annular space beyond the bypass element 120). And when the annular flow ports 145 are aligned with the bypass ports 125 (to allow longitudinal annular flow upward through the bypass element), the radial ports 142 would be out of alignment with the mandrel ports 117 (to block/prevent radial flow outward from the bore through the housing). The upper surface of the sleeve/face flange 144 may also have sealing properties, so that when the annular flow ports are out of alignment with the bypass ports, the face flange 144 may interface with the bypass element to form an effect seal (blocking/sealing the bypass ports to prevent annular flow therethrough).

In FIGS. 1A-1B, the sleeve 140 may be limited to only a certain amount of rotation with respect to the housing 110. For example, the sleeve 140 of FIG. 1A may be limited to approximately 90 degrees of rotation with respect to the housing 110. In the tool of FIGS. 1A-B, this limited rotation may result from the interaction of one or more bolts (for example extending from the bypass element) with one or more corresponding slots (for example, the annular flow ports in the face flange 144). This type of interaction may be better seen in FIGS. 1AA and 1BA. For example, in FIGS. 1AA and 1BA, the annular flow ports 145 may be slots (for example, openings that are the same width as the bypass ports, but are elongated to form a longer arc than the bypass ports), and bolts 127 may extend from the bypass element 125 (downward) through the slots (e.g. annular flow ports). Thus, the bolts 127 would limit the amount of rotation of the sleeve with respect to the housing (and bypass element) to approximately 90 degrees. FIG. 1AA shows the annular flow ports/slots 145 when they are aligned with the bypass ports 125 (e.g. the first configuration of the tool), for example after maximum allowed right hand rotation (of the sleeve with respect to the housing). FIG. 1BA shows the annular flow ports/slots 145 when they are out of alignment with the bypass ports 125 (not shown, since blocked by the face flange 144) (e.g. the second configuration of the tool), for example after maximum allowed left hand rotation (of the sleeve with respect to the housing). So, the bolts in the slots might operate as a stop mechanism, allowing only limited range of rotational movement of the sleeve with respect to the housing in order to alter the tool configuration. Any further rotation of the housing/tool string beyond that point would result in the sleeve and housing rotating together (for example, during cutting).

Furthermore, the sleeve 140 of FIG. 1A comprises a rotational position retaining/restraining element 147, which is operable to restrict rotational movement of the sleeve. In practice, the rotational position retaining element 147 may engage/interact with the casing (for example, causing drag/friction) to limit movement of the sleeve 140 during rotation of the tool string/housing. This allows the sleeve 140 to rotate with respect to the tool housing 110, when the tool string is rotated, and may allow for rotation of the tool string/housing to be used to shift the tool from its first configuration to its second configuration (and vice versa), for example by altering the rotational position of the sleeve 140 with respect to the housing 110. Typically, the grip of such a rotational position retaining element would be loose enough so that once the sleeve rotation reaches its maximum offset in one direction with respect to the housing (i.e. hits the stop mechanism), the tool string might still be capable of rotation (for example, with the rotational position retaining element slipping during cutting). In FIG. 1A, the rotational position retaining element 147 may comprise one or more (typically a plurality of) spring loaded dog elements 148, operable to push outward against the casing during use of the tool. FIGS. 1AB and 1BC further illustrate such dog elements 148. The dog elements typically provide frictional resistance to rotation relative to the casing, similar to a brake pad against a rotor in automotive applications. The dog elements 148 of FIGS. 1AB and 1BC typically would be recessed into pockets within the sleeve and would be energized (e.g. pressed outward) against the casing via internal spring members. Additionally, the sleeve 140 may typically be biased upward so that the face flange/seal 144 of the sleeve 140 may be in (sealing) contact with the bypass element (helping to provide an effective seal), and in FIG. 1A (compression) spring 150 provides this biasing force. The spring 150 typically would be compressed during assembly of the tool and would remain in compression during operation. The spring typically outputs enough force to maintain the face flange seal energized (e.g. pressed up against the bypass element). The spring design can be one of many different types (e.g. coil, bellville washer stack, wave, etc.). By using a spring or other biasing mechanism to hold the face flange 144 in (sealing) contact with the bypass element, the sleeve may be shifted downward by sufficient downward fluid pressure in the annulus (for example, allowing reverse pumping to dislodge the ball from the shoulder within the bore of the housing if it is desirable to re-open the sealed bore), while preventing upward flow in the annulus above the bypass element. In alternate embodiments (in which such reverse circulation may not be desired), the sleeve might instead have its longitudinal position fixed with respect to the housing/bypass element.

The tool 100 (and/or the tool string 102) of FIG. 1A also may comprise stabilizer elements 160, which may be operable to help centralize the tool/tool string in the cased wellbore. In FIG. 1A, the stabilizer elements 160 comprise a plurality of fins extending outward to approximately the casing inner diameter. And in FIG. 1A, the stabilizer elements may be free to rotate about the housing. FIG. 1AC may further illustrate such stabilizer elements 160. And in FIG. 1A, the longitudinal bore is not of uniform diameter through the entire length of the housing 110, but further includes a necked-down portion (e.g. having a smaller diameter than portions of the bore located above the necked-down portion) forming a shoulder 116. This shoulder 116 in the bore 115 may operate/serve as a ball/plug seat during operation of the tool downhole, allowing a ball/plug to be dropped/pumped downhole to seat on the shoulder to seal the bore (preventing flow further down the longitudinal bore 115).

So, the tool of FIGS. 1A-B has two configurations, based on rotation (rotational position) of the sleeve with respect to the housing. The sleeve is operable to open and close the radial mandrel ports in the housing and the longitudinal bypass ports in the bypass element of the housing based on its rotational position with respect to the housing (moving from the first to the second configuration), in an offsetting manner (such that when one is closed, the other is open, and vice versa). FIG. 1A illustrates the tool 100 in the first configuration, with the sleeve in its first position. In the first position (of the sleeve), the radial ports 142 in the sleeve are not aligned with the mandrel ports 117 in the housing body (such that the sleeve closes/seals the mandrel ports in the housing to prevent fluid flow from the bore to the annular space through the housing), but the annular flow ports 145 in the face seal 144 are aligned with the bypass ports 125 in the bypass element 120 (see for example FIG. 1AA, such that fluid may flow through the packer cup/bypass element in the annular space between the housing and the casing—e.g. allowing fluid communication in the annular space from below the packer cup to above the packer cup). In the first configuration, fluid flow in the bore 115 is contained in the bore until exiting the tool/tool string (for example, at the bottom end of the tool string), and fluid may flow in the annular space without restriction (see for example, FIGS. 3A-3C).

FIG. 1B illustrates the tool 100 in the second configuration, with the sleeve in its second position. In the second position of the sleeve 140, the radial ports 142 in the sleeve are aligned with the mandrel ports 117 in the housing body (see FIG. 1BB for example, allowing fluid communication from the bore to the annular space, such that fluid in the bore may flow into the annular space), but the annular flow ports 145 in the face seal 144 are not aligned with the bypass ports 125 in the bypass element 120 of the housing (see FIG. 1BA for example, such that the face/flange seal closes/seals the bypass ports to prevent fluid flow in the annular space from below the packer cup to above the packer cup—e.g. the tool no longer allows annular fluid flow upward past the sealed packer cup/bypass element). In the second configuration, fluid may flow from the bore radially outward through aligned mandrel and radial ports into the annular space, but the fluid in the annular space is restricted so that it cannot flow upward beyond the bypass element (which is sealed due to unaligned annular flow ports and bypass ports (see for example, FIGS. 4A-4D)).

By using the two configurations of the tool of FIGS. 1A-B, fluid flow may be diverted to assist in cutting and removal of casing from a wellbore. Typically, the tool 100 would be used in a tool string 102 (as shown in FIG. 2, for example), and the tool string might comprise a resettable casing spear 175 (operable to be set and unset by rotation), a motor 174 operable to be powered by fluid flow through the bore, and a cutter 173 operable to cut the casing when powered by the motor. Typically, the spear 175 would be located above the tool 100, and the motor 174 and cutter 173 would be located below the tool. And in some embodiments, the tool string would also include magnets (typically located below the tool but above the cutter). Typically, the spear 175 would be configured/operable to set when rotated the same direction used to position the tool 100 in the first configuration (for example, rotation right in the embodiment of FIG. 1A), and the spear 175 would be configured/operable to unset when rotated the same direction used to position the tool 100 in the second configuration (for example, rotation left in the embodiment of FIG. 1B). As FIGS. 3A-7 show, the tool might be used during cutting and extraction of casing from a wellbore, with rotation of the tool string being used to switch between configurations to control fluid flow pathways. These figures will be discussed below in more detail, with regard to methods/uses of a tool string.

So, embodiments may also comprise methods of forming up and/or using a tool in a wellbore (for example to assist in cutting and pulling casing out of a wellbore). An exemplary method (of forming and/or operating a tool in a cased wellbore and/or extracting casing from a wellbore) might comprise one or more of the following steps: making/forming up a tool string (having a longitudinal bore therethrough) comprising a rotatable/resettable spear (e.g. a spear operable to be set or unset based on rotation, for example with the spear being set by rotation the direction operable to move/ensure that the tool is in the first configuration, such as right hand rotation), a cutter (for example, an expanding-blade cutter operable to cut casing in a wellbore), a motor (operable to power the cutter, for example a motor operable to be powered by fluid flow through the tool string (e.g. longitudinal bore of the tool string)), and a tool for selectively diverting fluid flow (for example, from the longitudinal bore to the annular space between the tool and the cased wellbore and/or allowing or preventing fluid flow upward in the annular space above the tool, using/having mandrel ports and bypass ports, for example (such as exemplary FIG. 1A-B)) which has a first position (with mandrel port(s) closed and bypass port(s) open), and a second position (with mandrel port(s) open and bypass port(s) closed); wherein: the tool is operable to be changed from the first position/configuration to the second position/configuration by rotation; the spear is typically located above the tool in the tool string; and the motor and cutter are typically located below the tool in the tool string. FIG. 2 illustrates such an exemplary tool string 102. In some embodiments, the method might (further) comprise running the tool string downhole (in the cased wellbore 185), as shown in FIG. 2 for example; setting the spear by rotation of the tool string (for example, right hand rotation); positioning/configuring the tool in the first position/configuration (as shown in FIGS. 3A-3C, for example, with mandrel port(s) closed and bypass port(s) open, so that fluid is operable to flow downward through the bore of the tool string (exiting the bottom of the tool string, for example, below the cutter) and then to flow upward to the surface in the annular space between the tool string and the casing of the cased wellbore—e.g. circulate the wellbore)) by rotation (e.g. the same rotation as used to set the spear, for example right hand rotation, with a single rotation being used to set the spear and position the tool in the first position); making a cut to the casing of the cased wellbore (by rotating the tool string in the direction for setting the spear and positioning the tool in the first position/configuration (e.g. right hand rotation) while pumping/circulating fluid down the bore of the tool string (to power the motor and thereby the cutter) (and up the annular space, with fluid passing through the bypass port(s) of the tool)); and/or positioning the tool in the second position (as shown in FIGS. 4A-4D, for example, closing the bypass port(s) and opening the mandrel port(s)) by rotation (for example, rotation opposite that used to position the tool in the first position/configuration, e.g. left hand rotation). Additionally, some embodiments might comprise overpulling (for example, pulling up on the tool string), typically after setting the spear and before making a cut.

In some embodiments, once the cutting is completed, the method might comprise dropping a ball/plug to seal the longitudinal bore below the tool and above the motor and cutter (e.g. to seat in the bore beneath the mandrel ports of the tool and above the cutter and motor, for example on a shoulder at a narrowed portion of the bore of the tool string); and flowing fluid through the bore, through the mandrel port(s) of the tool, down to the cut in the casing (and hopefully circulating up to the surface on the exterior of the casing (e.g. between the casing and the wellbore surface) (e.g. attempting to circulate the well, as shown in FIG. 4D, for example). If circulation is not possible (all the way up to the surface), then method embodiments might further comprise unsetting the spear (e.g. by rotating the spear in the opposite direction used to set the spear—e.g. rotating left); extracting the ball from the bore (e.g. by rotating to position the tool in the first position/configuration (which might be done by the same rotation used to unset the spear) and reverse pumping/circulating the well (e.g. pumping fluid down the annular space and up the longitudinal bore)); repositioning the tool string (longitudinally) in the well (e.g. pulling the tool string up to reposition the cutter higher in the well, for example, if previously unable to circulate); re-setting the spear (for example by rotation—e.g. rotating right); overpulling the tool string; repositioning/reconfiguring the tool by rotation to its first position/configuration (for example, the same rotation used to re-set the spear—e.g. rotating right) (so that the mandrel port(s) are closed and the bypass port(s) are open, as shown in FIG. 5, for example); making a subsequent cut at the new position/location/depth in the well (for example, by rotating and pumping fluid down the bore, as described above, while the tool is in the first position/configuration); repositioning/reconfiguring the tool by rotation (e.g. left rotation) to its second position/configuration (as shown in FIG. 6, for example, with mandrel port(s) open and the bypass port(s) closed); dropping the ball/plug (a second time) to seal the bore below the tool and above the motor and cutter (e.g. to seat in the bore beneath the mandrel ports of the tool and above the cutter and motor, for example on the shoulder at a narrowed portion of the bore of the tool string); and/or flowing fluid through the bore, through the mandrel port(s) of the tool, down to the cut in the casing (and hopefully circulating up to the surface on the exterior of the casing (e.g. between the casing and the wellbore surface) (e.g. attempting to circulate the well). This process might be repeated as many times as necessary in order to circulate to the surface.

And once circulation up to the surface has been successfully accomplished, method embodiments might further comprise the steps of unsetting the spear (by rotation—e.g. left rotation); pulling the tool string up (to locate the spear just below the well head); resetting the spear (by rotation—e.g. right rotation) just below the well head (e.g. setting the spear at the top of the well, e.g. just below the well head); and/or extracting the cut casing (e.g. by pulling the casing upward using the spear, as shown in FIG. 7 for example). This may allow the cut casing (e.g. at least the uppermost cut segment of casing, for which circulation has been successful) to be pulled out of the well. And in some embodiments, one benefit of the method embodiments would be cutting and pulling the casing in a single trip of the tool string downhole (e.g. there would be no need to pull the tool string out of the well and/or re-insert the tool string into the well more than once). Persons of skill will understand these and other possible benefits regarding the disclosed embodiments.

While various embodiments in accordance with the principles disclosed herein have been shown and described above, modifications thereof may be made by one skilled in the art without departing from the spirit and the teachings of the disclosure. The embodiments described herein are representative only and are not intended to be limiting. Many variations, combinations, and modifications are possible and are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. And logic flows for methods do not necessarily require the particular order shown, or sequential order, to achieve desirable results. Other steps may be provided, or steps may be eliminated, from the described flows/methods, and other components may be added to, or removed from, the described devices/systems. So, other embodiments may be within the scope of the following claims.

Accordingly, the scope of protection is not limited by the description set out above, but is defined by the claims which follow, that scope including all equivalents of the subject matter of the claims. In the claims, any designation of a claim as depending from a range of claims (for example #-##) would indicate that the claim is a multiple dependent claim based of any claim in the range (e.g. dependent on claim # or claim ## or any claim therebetween). Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention(s). Furthermore, any advantages and features described above may relate to specific embodiments, but shall not limit the application of such issued claims to processes and structures accomplishing any or all of the above advantages or having any or all of the above features.

Additionally, the section headings used herein are provided for consistency with the suggestions under 37 C.F.R. 1.77 or to otherwise provide organizational cues. These headings shall not limit or characterize the invention(s) set out in any claims that may issue from this disclosure. Specifically and by way of example, although the headings might refer to a “Field,” the claims should not be limited by the language chosen under this heading to describe the so-called field. Further, a description of a technology in the “Background” is not to be construed as an admission that certain technology is prior art to any invention(s) in this disclosure. Neither is the “Summary” to be considered as a limiting characterization of the invention(s) set forth in issued claims. Furthermore, any reference in this disclosure to “invention” in the singular should not be used to argue that there is only a single point of novelty in this disclosure. Multiple inventions may be set forth according to the limitations of the multiple claims issuing from this disclosure, and such claims accordingly define the invention(s), and their equivalents, that are protected thereby. In all instances, the scope of the claims shall be considered on their own merits in light of this disclosure, but should not be constrained by the headings set forth herein.

Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Use of the term “optionally,” “may,” “might,” “possibly,” and the like with respect to any element of an embodiment means that the element is not required, or alternatively, the element is required, both alternatives being within the scope of the embodiment(s). Also, references to examples are merely provided for illustrative purposes, and are not intended to be exclusive.

Also, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other systems, modules, techniques, or methods without departing from the scope of the present disclosure. Other items shown or discussed as directly coupled or communicating with each other may be indirectly coupled or communicating through some interface, device, or intermediate component, whether electrically, mechanically, or otherwise. Other examples of changes, substitutions, and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein. 

What is claimed is:
 1. A tool for use in a downhole tool string within a cased wellbore, comprising: a mandrel housing configured to be made up as part of the tool string, with a longitudinal bore therethrough, one or more mandrel ports penetrating radially from the bore through the housing, and a bypass element located above the one or more mandrel ports and having one or more bypass ports therethrough; an annular seal located about the exterior of the bypass element of the housing and configured to sealingly engage the cased wellbore; and a sleeve disposed on the exterior of the housing for rotational movement with respect to the housing between a first position and a second position; wherein: the sleeve comprises one or more radial ports, a face flange operable to interface with the bypass element to seal annular flow therethrough, and a rotational position retaining element; the face flange comprises one or more annular flow ports; in the first position, the radial ports in the sleeve are not aligned with the mandrel ports in the housing body, but the annular flow ports in the face flange are aligned with the bypass ports in the bypass element; and in the second position, the radial ports in the sleeve are aligned with the mandrel ports in the housing body, but the annular flow ports in the face flange are not aligned with the bypass ports in the bypass element of the housing.
 2. The tool of claim 1, wherein the sleeve is configured to open and close the radial mandrel ports in the housing and the longitudinal bypass ports in the bypass element of the housing in an offsetting manner, such that when one is closed, the other is open, and vice versa.
 3. The tool of claim 1, wherein the tool is configured to be operated by rotation of the housing.
 4. The tool of claim 1, wherein the rotational position retaining element comprises one or more drag blocks.
 5. The tool of claim 1, wherein the sleeve is operable to rotate with respect to the housing.
 6. The tool of claim 1, wherein the annular seal is configured to rotate freely with respect to the housing.
 7. The tool of claim 1, wherein the longitudinal bore of the housing comprises a necked-down portion with a smaller inner diameter forming a shoulder, and wherein the shoulder is located below the mandrel ports.
 8. The tool of claim 1, wherein the sleeve is biased upward against the bypass element.
 9. The tool of claim 1, further comprising stabilizer elements operable to help centralize the tool in the cased wellbore.
 10. The tool of claim 1, wherein the tool string further comprises a cutter and a motor, wherein the motor powers the cutter, wherein the motor and cutter are located below the mandrel ports, and wherein the motor is configured to be powered by fluid flow through the bore, which then circulates back to the surface through the annular space.
 11. The tool of claim 1, wherein the tool string further comprising a spear.
 12. The tool of claim 11, wherein the spear comprises a rotatable, resettable spear.
 13. The tool of claim 10, wherein the tool string further comprises one or more magnets located below the mandrel ports and above the cutter.
 14. A method of extracting casing from a wellbore, comprising the steps of: forming up a tool string having a longitudinal bore therethrough comprising a resettable spear, a cutter, a motor configured to power the cutter, and a tool for selectively diverting fluid flow from the longitudinal bore to an annular space between the tool and the cased wellbore via one or more mandrel ports and selectively allowing fluid flow upward in the annular space above the tool via one or more bypass ports, with the tool having a first position with the mandrel ports closed and the bypass ports open, and a second position with the mandrel ports open and the bypass ports closed; wherein: the tool is operable to be changed from the first position to the second position by rotation; and the motor and cutter are located below the tool in the tool string.
 15. The method of claim 14, further comprising: running the tool string downhole in the cased wellbore; setting the spear by rotation of the tool string; placing the tool in the first configuration by rotation; making a cut to the casing of the cased wellbore; and placing the tool in the second configuration by rotation opposite that used to position the tool in the first position.
 16. The method of claim 15, wherein a single rotation of the tool string sets the spear and places the tool in the first configuration.
 17. The method of claim 16, wherein the cut is made by rotating the tool string in the direction for setting the spear and positioning the tool in the first position, while pumping fluid down the bore of the tool string to power the motor.
 18. The method of claim 15, further comprising overpulling the tool string after the spear has been set and before making the cut.
 19. The method of claim 15, further comprising: dropping a ball to seal the longitudinal bore below the mandrel ports of the tool and above the cutter and motor; and flowing fluid through the bore, through the mandrel ports of the tool, and down to the cut in the casing.
 20. The method of claim 19, further comprising: unsetting the spear by rotating the tool string in the opposite direction used to set the spear; placing the tool in the first configuration by the same rotation used to unset the spear; reverse pumping the well to extract the ball; repositioning the tool string in the well at a new depth; re-setting the spear, and placing the tool by rotation to its first configuration; making a subsequent cut at the new depth in the well; placing the tool by rotation to its second configuration; dropping the ball to seal the bore below the mandrel ports of the tool and above the cutter and motor; and flowing fluid through the bore, through the mandrel ports of the tool, down to the subsequent cut in the casing. 